Unconventional development of oil and gas shale and tight reservoirs has globally become very active in the past ten years due to advances in hydraulic fracturing operations. Due to the tightness of the shale rock formations (generally much less than 1-md and often measured in nano-darcy), hydraulic fracturing enables enhanced production by providing more contacts with the reservoir and allow ease of fluid production into the wellbore.
Hydraulic fracturing generally entails injecting a fluid into the wellbore at a sufficient rate and pressure to part or open existing fractures and/or overcome the tensile strength of the formation and, in the case of shallow, horizontal fractures, the formation overburden pressure. The injected fluid (“fracturing fluid”) creates cracks or fractures extending from the wellbore out into the formation, which may be often propped open with a proppant entrained in the fluid. The fractures permit hydrocarbons and other fluids to flow more freely into or out of the wellbore.
It is desirable to optimize the physical and chemical properties of a fracturing fluid. A fracturing fluid should be compatible with the reservoir rock and reservoir fluids, have sufficient viscosity and structure to suspend proppants if present, and transport them deep into the formation, be stable enough so as to retain sufficient viscosity and structure throughout proppant placement, possess low fluid losses properties, be easily removed from the formation, present low fluid flow friction pressures, be easily made under field conditions, be relatively inexpensive, and exhibit high levels of rheological performance.
Each shale play and reservoir inherently contains different rock and fluid types of varying properties. The reservoir interaction to a specific fracturing fluid can vary significantly and result in different production outcomes. In the prior art, different fracturing fluid compositions are tested for a particular reservoir until one chemistry (composition) is found that provides fracture effectiveness for operation and cost. The trial-and-error process can consume significant time and cost until a fluid is found for a particular reservoir.
Different types of fracturing fluids have been tried in the prior art. Dispersing fracture fluids are those which include aqueous solutions of monovalent cation salts, including organic sulfates, phosphates, chlorides, fluorides, citrates, acetates, tartrates, hydrogen phosphates or a mixture thereof. A dispersing fracture solution in the fracture zone will disperse clays and other earthen particles and allow them to be carried by the flow-back fluids out of the hydrocarbon producing fracture zone. This process increases hydrocarbon production when the pay zone does not contain a lot of clay. Aggregating fracture fluids are those which include aqueous solutions of di- and trivalent cation salts, e.g., calcium chloride (CaCl2), iron chloride (FeCl3), magnesium chloride (MgCl2), di- and trivalent metal salts of carboxylic acids. An aggregating fracture solution will aggregate and bind clays and other earthen materials. This stabilizes the fracture zone but will eventually clog and occlude the pay zone with the clay particles that are not aggregated by the cation salts. Many fracturing fluid materials when used in un-optimized concentrations have relatively poor “clean-up” properties, meaning that such fluids undesirably reduce the permeability of the formation and proppant pack after fracturing the formation.
There is still a need for improved methods and systems to characterize and optimize fracturing fluid chemistry. There is also a need for improved methods and systems to optimize fracturing fluid chemistry taking into consideration of factors including but not limited to imbibition, diffusion and interrelations between the fracturing fluid and reservoir rock in the fracturing fluid chemistry optimization (FFCO).